Rule 21 Working Group 3

Transcription

1 Rule 21 Working Group 3 SIWG CALL ISSUES 27 AND 28 JANUARY 11, 218 HT TPS://ZOOM.US/J/

2 Agenda 2:3-2:55 Regulatory updates, including PG&E presentation of smart inverter working paper 2:55-3:1 Review Issue brief (Jan 4) from last call 3:1-3:25 Proposals from parties 3:25-3:55 Discussion of topics 1-8 from Jan 4 issue brief 3:55-4: Next steps 2

3 Smart Inverter Working Group Issues 27 & 28 PG&E Presentation: Smart Inverter EPIC Demonstrations and Joint IOU SI White Paper January 11 th, 219

4 PG&E Smart Inverter EPIC Demos and Joint IOU SI White Paper Agenda: 1. EPIC 2.3A SI Demo Background 2. SI Demo Objectives 3. Technical Results, Learnings, and Challenges: A. Location 2 Field Testing B. Lab Testing C. SI Modeling 4. Joint IOU SI White Paper Framework 4

5 Installed Capacity (MW-AC) Smart Inverters: A Key Technology Enabling CA DER Policy Why did PG&E undertake this EPIC project? Smart Inverters can make autonomous decisions that can help maintain grid reliability and power quality Currently, Smart Inverter penetration in CA is low, but policies and investments need to be adopted in anticipation of rapid growth in SIs By 221, approximately half of all behind-the-meter PV installations in CA will have Smart Inverters By 228, nearly all BTM PV in CA will have Smart Inverters 2, 15, 1, 5, CA Statewide BTM PV Capacity and SI Penetration - 5% 5% SI-Enabled PV 228 1% 5

6 EPIC 2.3A Smart Inverter Demo Key Objectives Component SI Grid Impacts SI to Utility Communications SI Lab Testing SI Modeling Study Key Objectives Field-test SI impact to voltage on secondary and primary Measure customer curtailment from Volt VAR/Volt Watt LOCATION 1 INTERIM REPORT FINDINGS* Test capabilities of two types of SI aggregation platforms: 1) Vendor-specific platform 2) Vendor-agnostic platform Evaluate SI ability to execute Phase 1 & Phase 3 functions Test SI performance in edge cases (harsh grid conditions) Evaluate impact of PV and PV + storage with/without SIs on several Dx feeders Perform economic analysis of SIs vs. standard Dx upgrades *Link to PG&E EPIC 2.3A Smart Inverter Interim Report: 6

7 EPIC 2.3A Location 1 and Location 2 Field Tests Location 1: Residential behind-the-meter SIs + Vendor-Specific Aggregation Platform Location 2: Commercial behind-the-meter SIs + Vendor-Agnostic Aggregation Platform 15 assets, 62.5 kw capacity 14 assets, 4.5 MW capacity Mixed use feeders with moderate PV penetration Demo field assets account for <1% of peak feeder load No known power quality issues on feeders SI assets installed over first half of 217; tested through 11/17 Feeder with high penetration of commercial scale PV Demo field assets account for ~35% of peak feeder load Known voltage issues due to PV SI assets commissioned in early 218; tested through 9/18 7

8 Location 2 Example Field Test Site - SVD 1MW SVD Field Site 41 Inverters New comm. gateway Existing SI cluster controller Existing Inverter updated with new firmware/comm. gateway Existing satellite modem 8

9 Location 2 Field Demo Results 9

10 Example Location 2 Active/Reactive Power Measurements SI P and Q Measurements with Active Volt-Watt and Volt-VAR with Curve Set 1 Key Takeaways: Properly configured SIs successfully executed the Volt-Watt and Volt-VAR curve settings within tolerances, with a negligible percent of data points falling outside the tolerances Voltage on the feeder was elevated due to high PV penetration A total of 5 different VV/VW curves were tested 1

11 Voltage Violations by Volt-VAR/Volt-Watt curves across PV sites Site 1, 984 kw Site 2, 62 kw Site 3, 372 kw Site 4, 264 kw Site 5, 264 kw Site 6, 264 kw Site 9, 222 kw Site 1, 21 kw Key Takeaways: Enabling SI VV/VW curves reduced % of secondary high voltage violations on all sites The largest site (Site 2) experienced the fewest violations with VV/VW curves enabled Curves with more reactive power output were more effective in reducing high voltage violations No Volt-VAR/Volt-Watt 11

12 Primary Voltage by Volt-VAR/Volt-Watt curves across PV sites Unity Voltage -> Average Primary Feeder Voltage by Volt-VAR/Volt-Watt Curve Set No Volt-VAR/ Volt-Watt VV/VW Curve 1 VV/VW Curve 2 VV/VW Curve 3 VV/VW Curve 4 Key Takeaway: At the 35% feeder peak load PV penetrations tested, SI Volt-Watt/Volt- VAR showed no clear effect on elevated average primary feeder voltages. While the SI Volt-VAR and Volt-Watt functions are an important component of voltage regulation, the project has highlighted that SIs should be viewed as one component of a larger strategy referred to as integrated voltage regulation. 12

13 PV Production Curtailment Due to SI Volt-VAR/Volt-Watt Test Site PV Site Size (kw) % Production Curtailment by Curve Set Curve B1 Curve C1 Curve D1 Curve E1 Site Site Site Site Site Site Site Site Site Site Site Site Site Avg. Curtailment (%):.48 Key Takeaways: Customer generation curtailment due to activation of VV/VW curves on a feeder with persistent voltage violations was minimal Testing on average resulted in.48% curtailment at the SIs as compared to a baseline SI running no VV/VW curves Maximum curtailment observed across the Stage 3 sites and curve periods was 1.1% (Stage 2 = 1.2%) Amount of curtailment was not correlated with site size 13

14 Location 2: Key Learnings on Aggregation Platform/Communications Project Observations: Initial agg. platform firmware led to inconsistent application of SI settings and data transmission to PG&E. Communications/power outages at the test sites caused the agg. solution to shut down or lock up. In this project, satellite communications proved to be more reliable than cellular. Round-trip latency was lower for cellular vs. satellite. Key Takeaways and Recommendations: There is not yet an out-of-the-box vendor-agnostic SI aggregation solution that allows seamless interoperability between DERs, aggregators, and utilities. Aggregation platforms will need to be tailored and customized to specific DER communication infrastructure and DER use cases. Tools to identify and mitigate system failure (to increase end-to-end system reliability) need to be developed to have a situational view of SI assets and communication pathways. Degraded communication link quality testing should be included as part of any engineering, installation, and commissioning process (EIC) for SI-enabled DER aggregations. Cybersecurity standards are critical and need to be adopted by the industry and integrated into relevant communication standards for SI interconnection. 14

15 SI Lab Testing 15

16 Results of SI Lab Testing by PG&E Project Observations: While lab testing revealed issues with new SIs shipped in summer of 218, previously-commissioned SIs worked well in field testing. One vendor s product was defective out of the box and could not be lab-tested until a replacement was received. A second vendor s products did not function when the Rule 21 settings were applied, resulting in 3 SI failures. A third vendor s product shut down at 17% p.u. voltage although it was within the expected operating range. All three vendors products tripped/disconnected within.16s (9 cycles) upon opening of a line recloser, within IEEE requirements. Key Takeaways and Recommendations: SI vendor preparedness regarding Rule 21 Phase 1 Autonomous Function implementation needs improvement. Standardization of SI feature names and functions across mfrs. would significantly facilitate verification of configuration. Improved SI manufacturer product documentation is needed. Further progress needs to be made on capabilities to automate verification of deployed SIs against expected configurations. 16

17 EPRI SI Modeling 17

18 EPRI SI Modeling Study Background Key scope elements for the modeling study included: Detailed study of 6 representative PG&E distribution feeders in Open DSS Modeling of PG&E primary and secondary circuit topology & characteristics Evaluation of engineering standards for secondary voltage rise Inclusion of PV and PV + Storage (2% of all BTM interconnections now include storage) The study focused on comparing scenarios without smart inverters to scenarios with smart inverters, focusing on Volt-VAR/Volt-Watt Economic analysis of SI functions for grid support vs. traditional investment 18

19 EPRI Residential SI Modeling Voltage Violations from PV Maximum Transformer Count with Secondary Overvoltages (only residential PV systems modeled) PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 12 unctions 1 8 Reference Feeder LB Feeder ML Feeder NM Feeder SN Feeder WS Feeder W easuresconventional measures Feeder LB Feeder ML Feeder NM Feeder SN Feeder WS Feeder W Smart Inverter functions PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 PV1 PV2 PV3 PV4 Feeder LB Feeder ML Feeder NM Feeder SN Feeder WS Feeder W X Axis: Residential PV penetration vs. peak load: PV 1: 25% PV 2: 5% PV 3: 75% PV 4: 1% VV-R21 Combi-R21 Combi-R14 Key Takeaways: Modeled SI functions reduced, but did not entirely suppress overvoltage conditions arising from high PV penetration The reduction was comparable, and sometimes superior to the performance obtained with conventional upgrades such as new secondary (service) transformers. The SI modeling study was not able to demonstrate a scenario in which autonomous SIs mitigated a conventional upgrade on the primary, medium voltage system. Economic impact of SIs for ratepayers was VV-R21 very small, Combi-R21 but positive compared to Combi-R14 conventional secondary system upgrades. All three VV/VW curves were on average more effective than conventional upgrades; curves with more reactive power were more effective. 19

20 Component EPIC 2.3A Summary of Key Findings Key Findings SI Grid Impacts SI to Utility Communications SI Lab Testing SI Modeling Study Significant potential for voltage support from SIs to help mitigate local secondary voltage challenges caused by high PV penetration; no clear effect seen on the primary Customer curtailment from Volt-VAR/Volt-Watt was minimal (.4% avg., 1.2% max) SI aggregation platforms will need to be tailored and customized to specific DER communication infrastructure and DER use cases; no out-of-the-box solution exists Rigorous pre-deployment testing of SI aggregation platform software & firmware needed to ensure reliable behavior under degraded communication/grid power conditions Testing was heavily hindered by poor product readiness and SI equipment failures Unified standards, comprehensive testing and certification, and improved manufacturer product documentation and standardization of SI feature names and user interfaces needed Autonomous SI functions yielded a small but positive economic impact for ratepayers compared to conventional upgrades used to mitigate voltage issues from high PV penetration PG&E can eliminate its secondary voltage rise study process for BTM PV interconnection when Volt-VAR and Volt-Watt are activated, which will benefit customers and developers 2

21 California Joint IOU Smart Inverter White Paper Link to the Smart Inverter White Paper Link to the Smart Inverter White Paper Appendix Link to EPIC 2.3A Smart Inverter Interim Report EPIC 2.3A Final Report (Findings discussed above) available in Feb. EPIC 2.2 (DERMS) Final Report available later this month 21

22 SI White Paper Overview of CA Joint IOU SI Learnings Key Takeaway: Read the White Paper to learn more about CA Joint IOU SI Demonstrations 22

23 SI White Paper: Factors to enable DERs for Grid Services Issues already being addressed in IDER that Rule 21 should not duplicate: Can the grid need be met cost-effectively by DERs relative to traditional distribution upgrades? Are the deployed DERs incremental to what has already been forecasted by Distribution Planning, and is there any risk of double compensation? Are the DERs potentially creating additional issues/solving issues they created (e.g. reverse flow or elevated voltage from high PV penetration)? Can non SI-enabled DERs (Demand Response, Energy Efficiency, Permanent Load Shift, Electric Vehicles) meet the need? 23

24 Key SI White Paper Messages Location and volume of Smart Inverter-enabled DERs on the distribution grid is important Timing of Smart Inverter-enabled DER response should align with distribution grid need Availability and assurance of Smart Inverter-enabled DERs to provide grid response is needed Coordination between the utility and DERs or DER aggregators is important Grid modernization initiatives are necessary for Smart Inverter-enabled DERs to provide distribution grid services beyond autonomous Smart Inverter functions Unified standards, comprehensive testing and certification, and training for DER installers are needed to ensure consistent Smart Inverter operation, communication and cybersecurity 24

25 Value of EPIC to PG&E & CA State Policy Objectives 25

26 Thank You 26

27 27 Issues 27 and 28 Issue 27. What should be the operational requirements of smart inverters? What rules and procedures should the Commission adopt for adjusting smart inverter functions via communication controls? Issue 28. How should the Commission coordinate with the Integrated Distributed Energy Resource proceeding to ensure operational requirements are aligned with any relevant valuation mechanisms?

28 28 Phase 1 Phase 1 Autonomous Functions (approved April 215) Anti-Islanding Voltage Ride-Through Frequency Ride-Through Volt/VAR Control Default and Emergency Ramp Rates Fixed Power Factor Soft-Start Methods

29 Phase 2 Phase 2 Communications (approved April 217) Three Pathways: IOU DER IOU DERMS IOU Retail Aggregator Default Protocol: IEEE 23.5 (aka SEP 2.) Capability only, not yet functional communications 29

30 3 Phase 3 Phase 3 Advanced Functions 1. Monitor Key DER Data 2. DER Cease to Energize/Return to Service Request 3. Limit Maximum Real Power Mode 4. Set Real Power Mode 5. Frequency-Watt Mode 6. Volt-Watt Mode 7. Dynamic Reactive Current Support Mode 8. Scheduling Power Values and Modes

31 Issue Brief (Jan 4) 1. Define a clear line between non-valuation and valuation related operational requirements: Non-valuation side: operational requirements for reliability services, resiliency, grid support, mitigation of impact of DERs, avoided wire upgrades. Valuation side: operational requirements for grid services in the context of a market or communication protocol to capture a certain value stream. Needs narrowing, defining, and clarifying. Return to this after IDER gets further along with sourcing mechanisms. 31

32 Issue Brief (Jan 4) 2. Define use cases for non-default values: Use case #1: Adjust VOLT-VAR set-point to provide voltage support (with payment to customer?). Use case #2: Limit active power to a threshold in abnormal operating conditions. How and when? (Real-time for a specific circuit, and not a dynamic operational flexibility limit for ICA.) Other use cases? What does the grid need? 32

33 Issue Brief (Jan 4) 3. Define circuit-level blanket activation criteria: Under what conditions could (should) we use blanket activation of certain functions, rather than individual activation? (For example, circuit-level penetration threshold as a function of load or hosting capacity.) What is the range of non-default settings the utility can set? What are some alarms or similar measures to mitigate leaving functions activated for longer than intended? Proposed: communication activation would be on a going forward basis at interconnection. Retroactive activation would only be implemented by mutual agreement. 33

34 Issue Brief (Jan 4) 4. Which functions should be allowed by mutual agreement between the distribution provider and customer? Suggested: Telemetry Mitigating issues identified at time of interconnection Operation during abnormal conditions (e.g., a customer could choose to be controlled during abnormal conditions, rather than manually disconnected as may happen today) 34

35 Issue Brief (Jan 4) 5. Should our proposal be based solely on capabilities available today, or also include those capabilities to come along with IEEE 1547? 6. Should our proposal address implementation of Phase 2, and possible extensions to address the communication issues and testing challenges currently being faced with (by) aggregators? 7. Should our proposal provide limits ( rails ) on the adjustability of a function/parameter to ensure a customer isn t overly impacted (e.g. maximum slope of volt-watt, maximum curtailment, maximum cease to energize time)? 35

36 Issue Brief (Jan 4) 8. How does Gabe s framework, presented and extended below per the discussion, help us define operational requirements? Suggestion: let s focus first on operational requirements for (a) and (b). What are these requirements? Comment from Roger: we can already do (b) and (c). Comment from Gabe: for (e), the IDER proceeding will not be able to identify functions as well as this extended WG3-SIWG technical group could, so keep (e) as placeholder for future joint SIWG-IDER work. 36

37 Issue Brief (Jan 4) (a) Alternate settings that avoid upgrades (b) Emergency or temporary settings (c) Brand-new default settings (d) Transactional grid services with some type of compensation (e) Specific to IDER tariff (sourcing mechanisms) Opportunity for finding common ground in WG3 Open-ended, operational requirements not so clear Grey area between capabilities and tariffs Leave to (support) IDER at appropriate time Safety and reliability related Valuation-related (possible) Reiterates vision of DER Action Plan (Section 2.F) Use case #1: adjust VOLT-VAR setpoint Use case #2: limit active power output Use case #3:??? 37

38 Rule 21 Working Group Three Issue 27 Smart Inverters Brad Heavner CALSSA Policy Director January 11, 219

39 Goals of Issue 27 Proposal Issue 27: What should be the operational requirements of smart inverters? What rules and procedures should the Commission adopt for adjusting smart inverter functions via communication controls? Goals: Identify priority use cases Define procedures and rules for services anticipated from IDER tariffs Set target deployment of DERMS

40 Voltage Functions DERs can provide voltage support as a routine management tool or in response to abnormal conditions. Proposals for tariffs to facilitate this activity are due in the IDER proceeding (R ) on February 15. Smart inverters have three voltage functions. Changing from the default settings can provide grid support. Volt/Var Volt/Watt Fixed Power Factor (in place of Volt/Var)

41 Voltage Support Use Cases Change settings of voltage functions in response to feeder reconfiguration Procedure: Customer agrees to tariff (available in all locations) as part of interconnection application. When exercised, utility sends a command to facility or aggregator. Rule: Range of adjustability and frequency of use to be determined in IDER tariff. Schedule changes to settings of voltage functions to address seasonal differences Procedure: Utility determines locations where this is valuable. Customer agrees to tariff as part of interconnection application. Settings included in interconnection agreement or tariff agreement. Rule: Customer obligation to maintain schedule. Ongoing adjustments to settings of voltage functions in place of other voltage regulators Procedure: Utility offers agreement during interconnection review. When exercised, utility sends command to facility or aggregator. Rule: Aggregators use functionality as currently defined in Rule 21. Terms contained in IDER tariff.

42 Interconnection Use Cases Schedule changes to Limit Maximum Active Power (Function 3) in response to seasonal or hourly hosting capacity constraints Procedure: Customer proposes operational profile in interconnection application. Utility compares profile to hosting capacity in Screen M. Schedule contained in interconnection agreement. Rule: Customer obligation to maintain the schedule. Curtailment using DER Disconnect and Reconnect (Function 2) in response to abnormal grid operations to address operational flexibility constraints Procedure: Range of adjustability proposed by customer in interconnection application according to ICA-OF. Utility compares to hosting capacity in Screen M. When exercised, utility sends a command to facility or aggregator. Range of adjustability contained in interconnection agreement. Rule: Customer obligation to perform on command.

43 Other Use Cases System restoration When service is restored to a circuit after a grid outage, communication with smart inverters can stagger the timing of DERs coming back online to avoid voltage spikes Procedure: Utility sends a command to facility or aggregator prior to system restoration, or alternative start time is agreed to ahead of time. Rule: Customer obligation to perform, subject to coordination with IDER tariff. Storage dispatch as a capacity resource Procedure: Customer agrees to resource adequacy or demand response obligation. When exercised, utility sends command to facility or aggregator. Rule: Customer obligation to perform contained in tariff or solicitation.

44 DERMS Are Part of This Issue In order to utilize Phase 3 functions, utilities need to build communications systems on their end. Customers are required to deploy capabilities. Utilities should also be required to deploy capabilities. Utilities have built DERMS for pilot projects ordered by the CPUC. In Issue F, Working Group 4 will discuss the relationship of DERMS and the Operational Flexibility ICA constraint. That is only one use case. CALSSA requests that utility DERMS managers give an update on the Jan 31 SIWG call.

45 Next Steps 45